Retrieving hydrocarbons from subterranean reservoirs is becoming more difficult, as existing reserves are depleted and production becomes more expensive. It has been estimated that mature fields account for up to 70% of the world's production or more. In order to increase production, reservoirs are often “fractured” through explosions, pressure, heat, and other known methods. The cracks and spaces made after fracturing are filled with sands and small particles called proppants to keep the fracture open and allow the flow of hydrocarbons through the proppants. The total amount of fracturing including length, width, and volume of the fractures, size of openings, and penetration into the reservoir are directly related to the flow of hydrocarbons from the fractured reservoir.
It has become common practice to induce higher production rates from low permeability reservoirs by creating fractures via application of hydraulic pressure downhole (aka “frac'ing a well”). These fractures are held open by emplacing “proppant”, commonly sand or other highly permeable, inert material into the fracture. Hydrocarbon (usually gas) can then flow at increased rates to the wellbore via these highly permeable artificial fractures. Calculating flow from a fractured reservoir is dependent upon traditional fluid flow calculations and non-Darcy flow characteristics, since the combined effects may reduce flow near wellbore by more than 100-fold. The shape and flow in a fracture can have serious implications regarding effective fracture length. The effects of non-Darcy flow on the well productivity index are a function of proppant type and relative flow in the reservoir.
Some technologies have tried to determine the extent and position of a fracture using various imaging techniques. For example, William Shuck, U.S. Pat. No. 4,446,433, discloses transmitting and receiving antennae that penetrate the fracture and indicate fracture orientation and length. Funk, et al., US2008062036, measure propped fractures and down-hole formation conditions using radar imaging. Further, McCarthy, et al., WO2007013883, teach introducing a target proppant; transmitting electromagnetic radiation from about 300 megahertz-100 gigahertz; and analyzing a reflected signal from the target particle to determine fracture geometry. Lastly, Nguyen and Fulton, U.S. Pat. No. 7,073,581, describe electroconductive proppant compositions and related methods of obtaining data from a portion of a subterranean formation. Downhole imaging methods that both transmit and receive signals from within the borehole are extremely limited because detection is not separated from the formation. Because downhole detection is nearly linear, variations in the length of the fracture cannot be distinguished. Likewise, fluctuations in the depth and width of the fracture will be obscured by downhole detection. Fracture visualization must be improved to assess fractures quickly and inexpensively.
Because aging wells often produce from multiple intervals, some very thin, the ability to place these stimulation treatments with pinpoint accuracy is a key to more effective remediation and increased ultimate recovery. An accurate method of visualizing fracture length, proppant penetration, and estimated flow in the new fracture are required to accurately assess production capabilities and the need for further remediation before production is initiated. Presently, no means exists to accurately assess the location (direction and distance from the wellbore) of an artificially induced fracture containing proppant. Knowing this information is of prime importance to the completion engineer in order to determine if fracturing was successful and as a predictor of expected production rates from the well. Present techniques (passive seismic or micro-seismic) can give only indirect estimates of fracture direction and distance, and can not ascertain whether or not the fracture contains proppant along its complete length. Without new imaging technologies, the cost of fracturing and packing remediated wells quickly exceeds the profit margins for mature production if multiple runs are required to assess fractures, packing, and flow.